EP4623184A1

EP4623184A1 - A method of installing a permanent downhole sensor

Info

Publication number: EP4623184A1
Application number: EP23805982.8A
Authority: EP
Inventors: Walter STAM
Original assignee: Shell Internationale Research Maatschappij BV
Current assignee: Shell Internationale Research Maatschappij BV
Priority date: 2022-11-22
Filing date: 2023-11-16
Publication date: 2025-10-01
Also published as: WO2024110292A1

Abstract

A method of installing a sensor unit in a wellbore tubular arranged with the borehole, comprising a tubular bore. A punch tool is run into the tubular bore to a desired depth, and the sensor unit is pushed by the punch tool into a wall of the wellbore tubular. The punch tool is subsequently removed from the tubular bore, while leaving the sensor unit behind in the wall.

Description

A METHOD OF INSTALLING A PERMANENT DOWNHOLE SENSOR

FIELD OF THE INVENTION

In one aspect the invention relates to a method of installing a permanent downhole sensor.

BACKGROUND TO THE INVENTION

Oil and gas wells are normally completed with a production tubing. Such production tubing may be equipped with permanent downhole pressure sensor, for measuring tubing pressure. Conventionally, such permanent downhole pressure sensor is mounted externally on the tubing onto a port in the tubing wall. Such systems are typically not retrofittable on an already installed tubing.

Alternatively, there are also ported subs available which may carry a pressure gauge and be run into the production tubing. These are typically retrofittable. However, such subs generally restrict fluid flow thought the tubing.

SUMMARY OF THE INVENTION

In accordance with one aspect of the present invention, there is provided a method of installing a sensor in a wellbore tubular arranged with the borehole, comprising a tubular bore, comprising:

- providing a sensor unit;

- providing a punch tool;

- running said punch tool into the tubular bore to a desired depth;

- punching the sensor unit into a wall of the wellbore tubular;

- removing said punch tool from the tubular bore while leaving the sensor unit behind in the wall.

BRIEF DESCRIPTION OF THE DRAWINGS

The drawing figures depict one or more implementations in accordance with the present teachings, by way of example only, not by way of limitation. In the figures, like reference numerals refer to the same or similar elements. Fig. 1 shows a schematic cross-sectional view of a punch tool for punching a sensor unit in a wall of a wellbore tubular, the punch tool in a position about to be run in the wellbore tubular;

Fig. 2 shows a schematic cross-sectional view of the punch tool of Fig. 1 with punch arms in expanded position;

Fig. 3 shows a schematic cross-sectional view of the punch tool of Fig. 1 as it is being retrieved to surface;

Fig. 4 shows a schematic cross-sectional view of an embodiment of a sensor unit for use with the punch tool of Fig. 1;

Fig. 5 shows a schematic cross-sectional view of another embodiment of a sensor unit for use with the punch tool of Fig. 1;

Fig. 6 shows a photograph of a housing punched into a wellbore tubular; and

Fig. 7 schematically shows an example gas lift system comprising sensor units and unloading valves punched into a wellbore tubular.

DETAILED DESCRIPTION OF THE INVENTION

The person skilled in the art will readily understand that, while the detailed description of the invention will be illustrated making reference to one or more embodiments, each having specific combinations of features and measures, many of those features and measures can be equally or similarly applied independently in other embodiments or combinations.

The present disclosure provides for a sensor unit which can be punch-fitted into the wall of a wellbore tubular (such as a production tubing, a liner, or a casing). An advantage of punch fitting is that it can be applied to retrofit sensor units into an existing wellbore tubular which is already installed downhole, without removing the wellbore tubular from the well. Moreover, no pre-provided landing rims or landing nipples are required, so that the sensor units can be retrofitted at any desired depth or location as long as it is within reach of a punching tool. Once it has been retrofitted, the sensor remains in the tubular wall permanently (i.e., with no intention of removing or recovering while the tubular remains operative). Also, the sensor unit can be punched substantially flush with the inside wall of the wellbore tubular, thereby minimizing any flow restriction in the wellbore tubular.

The sensor unit is preferably housed in a substantially cylindrical or slightly frustroconical housing, which can be punched through the tubular wall with a punch tool. The sensor unit preferably comprises one or more of a sensing element, a power supply, a data storage device, and a data interface. The sensing element may be a pressure sensor or a temperature sensor. Alternatively, the sensing element may be a chemical sensor. The sensing element may comprise a micro-electro-mechanical system (MEMS).

Figs. 1 to 3 show a sequence of steps illustrating the method. Fig. 1 shows a view of a punch tool 1 for punching a sensor unit 17 in the wall of a wellbore tubular 11. The wellbore tubular 11 extends in a borehole 20 in an earth formation 10. The wellbore tubular 11 may typically have a bore having a certain inside diameter (ID). The wellbore tubular 11 may be a production tubing, or any other type of tubing such as casing or a liner. The wellbore tubular 11 may be surrounded by an open annulus, or it may be cemented. As depicted in Fig. 1, the punch tool 1 is about to be run in the wellbore tubular 11. The punch tool 1 comprises a tool housing 3, which extends along a longitudinal tool axis 2. The punch tool 1 is intended to be lowered into the bore of the wellbore tubular 11, in a direction parallel to the longitudinal tool axis 2. The punch tool 1 further comprises a punch arm 7, arranged within the tool housing 3. A major part of the punch arm 7 is cylindrical and extends along a longitudinal punch axis 8. The longitudinal punch axis 8 is substantially perpendicular to the longitudinal tool axis 2 and extending radially outward therefrom. The sensor unit(s) 17 is/are mounted on a distal end of the punch arm(s) 7.

A press device is provided to move the punch arm 7 along a trajectory in a radially outward direction from the tool housing 3, in a direction along the longitudinal punch axis 8, from a retracted position to an expanded position. As depicted in Fig. 1, the punch arm is in its retracted position. Any suitable press device may be employed. As a generic example, in the schematic of Fig. 1, the press device comprises a cylinder piston within a pressure chamber 9 which can be filled with a pressurized fluid to exert an outward directed force on the punch arm 7. Other press devices have been proposed in the art, such as devices that include a wedge to mechanically push the punch arm 7 outward. The present invention is not restricted to any particular press device.

Turning now to Fig. 2, the punch tool 1 has been lowered inside the bore of the wellbore tubular 11 in the direction of the longitudinal tool axis 2. The press device has been activated and the punch arm(s) 7 is/are now in expanded position(s). The punch arm(s) 7 have been moved in a radially outward direction from the tool housing 3 in each respective trajectory away from the longitudinal tool axis 2. As each punch arm 7 transitions from the retracted position to the expanded position, the punch arm 7 moves the sensor unit 17 towards the wall of the wellbore tubular 11. The sensor unit 17 is thus forced to penetrate into the wall of the downhole tubular 11. At the same time, the sensor unit 17 plugs a perforated hole created by the punch arm 7.

Referring now to Fig. 3, the punch tool 1 is being retrieved to surface by pulling the tool housing 3 up through the bore of the wellbore tubular 11. The sensor unit 17 has been severed or released from its punch arm 7, and preferably it is flush with the inner surface of the wall of the wellbore tubular 11. After severance, the remaining part of the punch arm 7 may be recovered to its retracted position to facilitate the retrieval to surface.

The sensor unit 17 stays behind in the wall of the wellbore tubular 11 and plugs the perforation. In certain embodiments, instead of the sensor unit 17, another type of functional plug may be deployed in this matter, such as an orifice and/or a nozzle, and/or a check valve (also called: non-retum valve) and/or an unloading valve for gas lift. Optionally, when there is more than one punch arm 7 in the punch tool 1, one of the punch arms 7 may be used to install a sensor unit 17 while another is used to install a different type of functional plug.

Figures 1-3 illustrate multiple sensor units 17 can be punched-in simultaneously. These can, for example, be pressure-sensing units or temperature-sensing units or chemical-sensing units. Different types of sensor units could be punched-in simultaneously, or a plurality of sensor units of the same type can be punched-in. Alternatively, the punch tool 1 can be used to punch-in units of other functionality, i.e., non-sensing functionality such as an orifice or valve.

Example sensor units 17 are schematically illustrated in Figs. 4 and 5. Each of these examples comprise a cylindrical housing 24, having a cylindrical sidewall and a lateral front face. When deployed, the lateral front face faces the wall of the wellbore tubular 11. The sensor unit 17 may comprise one or more receptacles 26 for receiving shear pins to mount the sensor unit 17 on the punch tool 1. These can break upon pulling the punch tool 1 back to the surface. Other severable connection methods may be employed instead.

The embodiment of Fig. 4 comprises a front cap 23, which is preferably removable from the cylindrical housing 24 to provide access to the internals of the cylindrical housing 24. These may include a sensing element 22 and one or more of: a battery 25 or other power supply, a data interface 27, an electronics unit 28, and/or a data storage device 29. The battery 25 may be connected to power any internal of the sensor unit 17. An access opening 21 may be provided, for example, in the front cap 23, to expose the sensing element 22 fluids in the wellbore. If necessary, additional fluid barriers may be provided between the sensing element 22 and any other of the internals.

The embodiment of Fig. 5 comprises a smaller front cap 23, and a rear cap 33. The rear cap 33 may be convenient for accessing the internals from the other side.

Electronic sensing signals produced by the sensing element 22 may be processed in the electronics unit 28 and outputted from the sensor unit 17 via the data interface 27. This may suitably be a wireless data interface. The sensor unit 17 may be provided with data storage device 29 to accumulate sensor data over a certain time interval. After the time interval has lapsed, the data may be retrieved from storage and outputted (e.g., in batch form) via the data interface 27 in a read-out operation.

The housing 24 may be essentially cylindrical, so that it can be punched in the wellbore tubular 11 from the inside. However, a small taper 18 (sometimes referred to as “chamfer” or “bevel”) may be applied to part of the cylindrical side wall of the housing 24 (such as shown in Fig. 5) and/or the front cap 23 (shown in Fig. 4), to provide a frustoconical shape. The effect of this is that a slightly smaller hole is punched out of the tubular 11 wall and that a slightly oversized part of the housing is then forced in the smaller hole to secure the housing 24 more rigidly in the tubular 11 side wall. The chamfer 18 may be optimized to enhance push-back resistance of the sensor unit 17 left behind in the wall of the tubular 11. The front face of the housing 24 is preferably substantially flat, so that the punch pressure is distributed over a significant area available on the housing 24 allowing the tubular 11 wall material to shear at the edges of the flat surface.

The outer diameter of the cylindrical housing 24 may be as small as 20 mm. The maximum diameter of the housing 24 is practically limited by the maximum force that the punch tool 1 is capable of delivering. Preferably, the maximum diameter is 30 mm, more preferably 25 mm. The minimum diameter of the housing 24 may be limited by the maximum compressive strength of the housing 24. The axial length of the sensor unit 17 can be selected in relation to the wall thickness of the tubular 11 side wall. However, there are also other functional requirements which need to be accounted for, as the sensor unit 17 needs to provide enough internal space to accommodate the sensing element and any auxiliary parts such as a power supply, a data storage device, and a data interface.

Fig. 6 shows a photograph of a housing as depicted in Fig. 5 above (20 mm diameter; 16 mm length), after punching into a 4.5 inch (approx. 11.43 cm) outer diameter wellbore tubular 11 of 171b/ft (approx. 25 kg/m) Pl 10 carbon steel. The corresponding wall thickness is about 9.6 mm. The front face of the cylindrical housing 24 can clearly be seen, as well as the small access opening 21 provided in the front cap 23. The wall piece 35 that has been punched out is also included in the photograph, which demonstrates the nice clean cut as punched out by the chamfered surface of the cylindrical housing 24.

Collapse tests were performed in the laboratory. A 20-mm diameter cylindrical housing 24 with a small chamfer 18 of 0.5 mm (reduction in radius, i.e., the diameter of the flat inlet surface was 1.0 mm smaller than the diameter of the cylindrical part of the housing 24) collapsed at push back force corresponding to a pressure differential of 45 MPa. As comparison, the collapse rating of the wellbore tubular 11 is 117 MPa. The same size housing 24 with alarger chamfer of 1.5 mm collapsed at 175 MPa. A clear benefit of the chamfer 18 is observed. Without wishing to be limited by theory, it is suggested that the chamfer 18 causes a slightly smaller hole to be created, by shear in the tubular 11 wall, and that the full diameter cylindrical part of the housing 24 is then inserted in a de-facto slightly undersized perforation whereby some radial elastic strain around the housing 24 is induced, which holds the housing 24 better in place. The chamfer 18 size can be optimized to maximize push back collapse properties, as it may vary with type and size of wellbore tubular and with size of the housing 24.

Fig. 7 schematically shows how the presently proposed method can be applied in a gas lift system. Several battery-powered pressure/temperature memory sensor units 17 are installed at various depths in the side wall of the production tubing 42, without causing any inner diameter restrictions, therefore avoiding additional pressure drop of the flow of produced fluids 5 in the tubing. An open annulus may surround the production tubing 42, which is typically sealed at the bottom with a production packer 47. The bottom of the open annulus, and the production packer 47, may be located near a lower end of the production tubing 42. A tubing nipple profile 13, shown at the lower end of the production tubing 42, may not be necessary when the method of the invention is employed.

The tubing may also be provided with unloading valves 12, at increasing depths in the production tubing 42. The unloading valves 12 are pierced through the side wall of the production tubing 42 to establish a valved fluid communication through the side wall of the production tubing 42 with flow direction from the annulus into the bore of the production tubing 42. The unloading valves 12 may also be punched-in, as described in International application No. PCT/EP2023/069306, filed 12 July 2023 (not yet published). Suitably, if the punch tool 1 has multiple punch arms 7, such as is the case in the example of Figs. 1-2, at least one of the arms 7 may be employed to punch-in the sensor unit 17 while at least one other arm 7 may be employed to punch-in the unloading valve 12 simultaneously.

Alternatively, or in addition thereto, other punch runs can be made, either exclusively with unloading valves 12, or exclusively with sensor units 17, or a combination of unloading valves 12 and sensor units 17.

Fig. 7 further illustrates an embodiment of the read-out of the sensor units 17, whereby a data read-out device 19 is lowered on wireline 4 and positioned near each sensor unit 17 to pull the data from the data interface 27. Subsequently the data may be processed and used to optimize the gas lift pressure and/or flow rate. Technology required for such wireless readout system is available commercially. Reference is made, for example, to Welltec Data Monitoring. The WDM™ is identified and activated by the wireless telemetry from a wireless data reader (WDR™) and transmits the data quickly from the data interface to the WDR™. (Welltec A/S Gy devang 25, 3450 Alleroed, Denmark.)

As mentioned above, the sensor units 17 or even the complete gas lift system can be retrofitted, by using a punch tool. A variation of punch tools has been described in literature, which may be, or may be modified to become, suitable for installing these valves. Reference is made to WO 2020/229440 Al; WO 2021/080434 Al; US 2,381,929; and US 2,544,601 which show various non-limiting examples. Another relevant punch tool is described in WO 2023/083946 Al. Such tools may be run rigless, for example on a wireline a slickline, a coiled tubing, or an e-line.

The person skilled in the art will understand that the present invention can be carried out in many various ways without departing from the scope of the appended claims.

Claims

1. A method of installing a sensor in a wellbore tubular arranged with a borehole, comprising a tubular bore, comprising:

- providing a sensor unit;

- providing a punch tool;

- running said punch tool into the tubular bore to a desired depth;

- punching the sensor unit into a wall of the wellbore tubular;

2. The method of claim 1, wherein the sensor unit comprises a sensing element, a power supply, and a data interface.

3. The method of claim 1 or 2, wherein the sensing element is a pressure-sensing element and/or a temperature-sensing element.

4. The method of any one of the preceding claims, wherein the sensor unit comprises a cylindrically shaped housing, having a cylindrical sidewall and a lateral front face facing the wall of the wellbore tubular, wherein a chamfer is provided between the front face and the cylindrical side wall, around the full circumference of the lateral front face, to enhance push- back resistance of the sensor unit left behind in the wall.

5. The method of any one of the preceding claims, wherein the wellbore tubular is a production tubing surrounded by an open annulus.

6. The method of claim 5, wherein the open annulus is sealed with a production packer near a lower end of the production tubing.

7. The method of claim 5 or 6, further comprising punching a plurality of unloading valves at increasing depths in the production tubing, to establish a valved fluid communication through a side wall of the production tubing with flow direction from the annulus into the tubular bore of the production tubing.

8. The method of any one of the preceding claims, wherein the wellbore tubular comprises an inside wall and wherein punching said sensor unit flush with the inside wall of the wellbore tubular without causing any inner diameter restrictions within the wellbore tubular.